Greenhouse gases, primarily carbon dioxide are emitted to the atmosphere, causing an effect in which heat reflected from the earth's surface is kept from escaping into space. Thus, there is concern that the atmospheric temperature will rise to cause global climate change. The primary options for carbon dioxide mitigation are improved fuel efficiency, use of low carbon fuels or alternative power sources, and carbon sequestration. The latter entails the capture and storage of carbon dioxide that would otherwise be emitted to the atmosphere. The greenhouse gases can be most effectively captured at the point of emission. The captured carbon dioxide can be stored in underground reservoirs.
Pulverized coal (PC) power plants are widely used for power. Flue gas produced from PC plants consists of about 12%-15% CO2 and 80%-85% nitrogen with the remainder mostly oxygen plus a trace amount of SO2, NOx, CO, and mercury. This CO2 concentration is far too low to be sequestered directly; therefore, it must first be concentrated to over 90%, or near purity, in order to be disposed of economically. The largest costs in carbon sequestration are those associated with capturing and concentrating the carbon dioxide from the flue gas at the source. The capture cost could account for more than two thirds of the sequestration cost. In traditional amine or amino acid salt based CO2 scrubbing process, SO2 could be removed by a flue gas desulfurization (FGD) process first to avoid the reaction of SO2 with amine or amino acid salt, resulting in the formation of heat stable salts, which cannot be regenerated by heat treatment.
Approaches being investigated for the capture and separation of carbon dioxide from flue gas streams include solvent, sorbent, membrane, chemical looping, oxy-combustion, and biological fixation-based approaches.
However, currently the state-of-the-art technologies for existing PC power plants are essentially limited to the solvent approach involving the use of amine absorbents. Monoethanolamine (MEA) has been comprehensively studied and successfully used for CO2 separation in natural gas purification. However, the MEA process suffers many drawbacks if used for the capture of CO2 from coal-fired power plants. These include: (1) high energy consumption (about 4.0-4.5 GJ/ton CO2) during solvent regeneration, (2) high carbamate decomposition temperatures (100° C.-120° C.), (3) low CO2 loading capacity (0.25-0.35 mol CO2/mol MEA), (4) high absorbent makeup rate due to amine degradation by SO2, NOx, HCl and oxygen in flue gas, and (5) high equipment corrosion rate, particularly when a high concentration of MEA is used.
A current commercial process involves using an inhibited 30 wt. % MEA for the capture of CO2 from flue gases. The use of a mixture of corrosion inhibitors with high concentration of MEA allows the use of carbon steel and gives the process a smaller reboiler steam demand than the processes employing 20% MEA. Preliminary analysis indicates that CO2 capture via MEA scrubbing and compression to 2,200 psi could raise the cost of electricity from a new supercritical PC power plant by 65 percent, from 5.0 cents per kilowatt-hour to 8.25 cents per kilowatt-hour.
In view of the drawbacks of MEA for CO2 capture, extensive efforts are being spent to develop a more cost-effective absorbent than MEA. Alternatives include MHI/KEPCO's KS-1, 2, and 3 (sterically hindered amines); Cansolv® Absorbent DC101™ (tertiary amines with a promoter); HTC Purenergy's mixed amine solvent; IFP's Castor; and Canadian's PSR. The hindered amines were claimed to have better properties than MEA, in terms of solvent regeneration energy consumption and corrosion rate.
Alternatively, amino acid salts and inorganic alkali are being tested for CO2 absorption. The advantages of amino acid salts include no chemical loss from vaporization and low degradation (less sensitive to oxidation by oxygen). Inorganic alkali is chemically stable, but the CO2 absorption kinetic is inferior to amines. Activators had previously been used with potassium carbonate to improve CO2 absorption mass transfer and inhibit corrosion. UOP's Benfield process (over 675 units worldwide) and Exxon's Flexsorb HP process involve hindered amine as activator. These systems were mainly used for recovering CO2 from industrial gas streams and are known as activated hot potassium carbonate (AHPC). Likewise, the blending of piperazine with potassium carbonate to increase CO2 absorption kinetics has been studied.
Two aqueous ammonia processes have recently been developed—Alstom's CAP (Chilled Ammonia Process) and Powerspan's ECO2. These processes take advantage of NH3's low cost and high CO2 loading capacity. Each of them has its own unique approach to overcome the problem of NH3 loss due to its high volatility. The Chilled Ammonia Process reduces NH3 emission during CO2 absorption by cooling the flue gas to very low temperature. The scaled-up demonstration of the Chilled Ammonia Process is being conducted by Alstom Power, EPRI, and We Energies at the Pleasant Prairie power plant, Wisconsin; also by Alstom Power, American Electric Power, and EPRI at Mountaineer Plant in New Haven, W.Va. On the other hand, the ECO2 Aqueous Ammonia Process captures NH3 emitted from the absorber to produce a dilute solution of NH3, and uses it upstream in the ECO system for SO2 absorption. As a result, NH3 loss is not wasted in the CO2 capture process. Powerspan is conducting further development of ECO2 at NRG's WA Parish plant near Sugar Land, Tex.
Ionic liquids have also been studied for CO2 capture because of their advantageous properties including high thermal stability, low vapor pressures, nonflammability, and nontoxicity.
The following patents and patent applications are directed to such related technology: U.S. Pat. Nos. 4,567,294; 4,217,237; 4,094,957; 4,217,237; 4,739,866; 4,814,104; 5,618,506; 5,744,110; 5,904,908; 7,056,482; 7,255,842; 7,601,315; 7,709,635; 7,744,838; U.S. patent application Ser. No. 10/551,834, filed Apr. 1, 2004; Ser. No. 10/548,853, filed Mar. 4, 2004; Ser. No. 11/371,924, filed Mar. 10, 2006; Ser. No. 11/046,561, filed Jan. 26, 2005; Ser. No. 12/622,947, filed Nov. 20, 2009; Ser. No. 12/459,685, filed Jul. 6, 2009; Ser. No. 12/488,230, filed Jun. 19, 2009; Ser. No. 12/406,289, filed Mar. 18, 2009; Ser. No. 12/406,360, filed Mar. 18, 2009; Ser. No. 12/101,087, filed Apr. 10, 2008; Ser. No. 11/632,537, filed Apr. 12, 2005, and Ser. No. 12/448,252, filed Dec. 4, 2009; and PCT Patent Application Pub. No. WO 03/095071A1.
WO 03/095071 A1 and U.S. 2010/0092359 A1 disclose a method for capturing CO2 from exhaust gas in an absorber, wherein the CO2 containing gas is passed through an aqueous absorbent slurry wherein said aqueous absorbent slurry comprises an inorganic alkali carbonate, bicarbonate and at least one of an absorption promoter and a catalyst, and wherein the CO2 is converted to solids by precipitation in the absorber, said slurry having the precipitated solids is conveyed to a separating device, in which the solids are separated off, essentially all of at least one of the absorption promoter and catalyst is recycled together with the remaining aqueous phase to the absorber. This disclosed method has the problem of plugging in the absorber.